Remediation of asphaltene-induced plugging of an oil-bearing formation

ABSTRACT

A system and method for remediation of asphaltene-induced fouling of an oil-bearing formation is provided wherein an asphaltene solvent comprising at least 75 mol % dimethyl sulfide is introduced into an oil-bearing formation containing asphaltene deposits and the dimethyl sulfide is contacted with the asphaltene deposits.

RELATED CASES

This application claims benefit of U.S. Provisional Application No. 61/832,272, filed on Jun. 7, 2013, which is incorporated herein by reference.

FIELD OF THE INVENTION

The present invention is directed to improving oil recovery from an oil-bearing formation fouled by asphaltene deposits. In particular, the present invention is directed to improving oil recovery from an oil-bearing formation fouled by asphaltene deposits using an asphaltene solvent to dissolve the asphaltene deposits.

BACKGROUND OF THE INVENTION

Production of oil from an oil-bearing formation may be impeded by hydrocarbonaceous deposits within the formation. Asphaltene deposits are one type of hydrocarbonaceous deposit that may impede the flow of oil through a formation by reducing the permeability of the formation. Asphaltenes are a fraction of crude oil formed predominately of aromatic hydrocarbons and heteroatom-containing hydrocarbons that are high in molecular weight relative to other components of the crude oil.

Production of oil from an oil-bearing formation may induce asphaltene flocculation in the formation, where the flocculated asphaltenes may aggregate and deposit in the formation to impede or block the flow of oil through the formation and thereby reduce the amount of oil that may be produced from the formation. Asphaltene flocculation may be induced, in particular, in the formation near a production well, where changes in pressure, temperature, composition, and shear rate caused by production of oil from the well may destabilize the asphaltenes in the oil near the production well and cause the asphaltenes to flocculate, aggregate, and deposit, plugging the formation near the production well.

In other formations, naturally occurring tar mats formed of asphaltenes may inhibit the flow of oil through the formation, blocking mobilization of the oil through the formation for production. These tar mats may form by destabilization of the asphaltenes in the oil within the formation in high permeability portions of the oil-bearing formation. The destabilized asphaltenes in the high permeability portion of the formation may flocculate, and the flocculated asphaltenes may aggregate and deposit in the formation and thereby form the tar mat.

Asphaltenes may deposit in the formation in the form of a solid deposit or a sludge. Solid deposits of asphaltenes may be a result of growth of asphaltene aggregates on formation surfaces, while sludges may form as large aggregates in solution that settle out.

Various solvents have been utilized to solubilize asphaltenes that have deposited in an oil-bearing formation to improve recovery of oil from the formation by increasing the permeability of the formation to mobilized oil. U.S. Pat. No. 5,425,422 discloses injecting deasphalted oil into an oil-bearing formation to solvate asphaltene deposits near a wellbore in the formation and thereby improve production of oil from the formation, where the injected oil is produced from the formation and deasphalted prior to being injected into the formation. The use of aromatic solvents such as o-xylene and toluene to dissolve asphaltene-based deposits in a formation near a wellbore is also known.

Disulfide solvents have also been used to dissolve asphaltene-based deposits in a formation for near-wellbore formation remediation. U.S. Pat. No. 4,379,490 discloses the use of an amine activated disulfide oil for treating and removing unwanted asphaltene deposits from the pore spaces of oil-bearing formations. U.S. Pat. No. 4,379,490 further discloses that carbon disulfide is one of the most effective asphaltene solvents known, and that it has been utilized for the removal of asphaltene-based deposits from oil-bearing formations.

Such solvents, however, have certain disadvantages attached to them. Injection of deasphalted oil to remediate asphaltene deposition in a formation is inefficient since it requires injecting oil produced from the formation and subsequently processed back into the formation, where some of the injected oil may not be recovered again from the formation. Injection of aromatics such as toluene and o-xylene may be subject to regulatory limitation, and is economically inefficient since such aromatics are even more highly processed and valuable than deasphalted oil. Disulfide solvents may be subject to hydrolysis within the formation, and, in the case of carbon disulfide, may result in souring the formation. Carbon disulfide is also highly toxic.

Improvements to existing methods of remediating asphaltene deposits and tar mats in oil-bearing formations are desirable.

SUMMARY OF THE INVENTION

In one aspect, the present invention is directed to a method of remediating asphaltene deposition in an oil-bearing formation, comprising:

providing an asphaltene solvent comprising at least 75 mol % dimethyl sulfide (DMS);

introducing the asphaltene solvent into an oil-bearing formation containing one or more asphaltene deposits; and

contacting the asphaltene solvent with one or more of the asphaltene deposits in the formation.

In another aspect, the present invention is directed to a system for remediating asphaltene deposition in an oil-bearing formation containing asphaltene deposits, comprising:

an asphaltene solvent comprising at least 75 mol % dimethyl sulfide (DMS);

an asphaltene solvent storage facility containing at least a portion of the asphaltene solvent; and

a well extending into the oil-bearing formation positioned to introduce the asphaltene solvent into the formation to contact an asphaltene deposit therein, the well being structured and arranged to introduce the asphaltene solvent into the oil-bearing formation to contact an asphaltene deposit therein, wherein the asphaltene solvent storage facility is operatively fluidly coupled to the first well to provide the asphaltene solvent to the first well.

BRIEF DESCRIPTION OF THE DRAWINGS

The drawing figures depict one or more implementations in accord with the present teachings, by way of example only, not by way of limitation. In the figures, like reference numerals refer to the same or similar elements.

FIG. 1 is a schematic diagram illustrating a system of the present invention that may be utilized to practice a method of the present invention.

FIG. 2 is a schematic diagram illustrating a system of the present invention that may be utilized to practice a method of the present invention.

FIG. 3 is a schematic diagram illustrating a system of the present invention that may be utilized to practice a method of the present invention.

FIG. 4 is a graph showing petroleum recovery from oil sands at 30° C. using various solvents.

FIG. 5 is a graph showing petroleum recovery from oil sands at 10° C. using various solvents.

DETAILED DESCRIPTION OF THE INVENTION

The present invention resides in the discovery that dimethyl sulfide (hereafter often referred to as “DMS”) is miscible with all fractions of crude oil except solid paraffin waxes, and in particular, that DMS is a highly effective asphaltene solvent. An asphaltene solvent comprising at least 75 mol % DMS is provided, and is introduced into an oil-bearing formation containing one or more asphaltene deposits. The solvent is contacted with the asphaltenes of the asphaltene deposits to solvate the deposited asphaltenes. The solvent may solvate a substantial portion of the asphaltenes in the asphaltene deposits to remove, or reduce the size of, the asphaltene deposits, which may increase the permeability of the formation. Mobilized oil then may be produced from the formation through the formation portion from which asphaltene deposits have been removed or reduced by contact with the solvent.

DMS exhibits solubility with asphaltenes similar to carbon disulfide. DMS, however, is relatively non-toxic, is not subject to hydrolysis at typical temperatures within oil-bearing formations, and may be produced from relatively low value components. DMS also has a low boiling point relative to most components of a crude oil, and may be easily separated from oil produced from the formation by flashing or distillation.

Certain terms used herein are defined as follows:

“Asphaltenes”, as used herein, are defined as hydrocarbons and heteroatom-containing hydrocarbonaceous materials that are insoluble in n-heptane and soluble in toluene at standard temperature and pressure. “Miscible”, as used herein, is defined as the capacity of two or more substances, compositions, or liquids to be mixed in any ratio without separation into two or more phases at equilibrium. “Near-wellbore”, as used herein, is defined as within 5 meters of a wellbore in an oil-bearing formation. “Operatively fluidly coupled” or “operatively fluidly connected”, as used herein, defines a connection between two or more elements in which the elements are directly or indirectly connected to allow direct or indirect fluid flow between the elements. The term “fluid flow”, as used herein, refers to the flow of a gas or a liquid; the term “direct fluid flow” as used in this definition means that the flow of a liquid or a gas between two defined elements flows directly between the two defined elements; and the term “indirect fluid flow” as used in this definition means that the flow of a liquid or a gas between two defined elements may be directed through one or more additional elements to change one or more aspects of the liquid or gas as the liquid or gas flows between the two defined elements. Aspects of a liquid or a gas that may be changed in indirect fluid flow include physical characteristics, such as the temperature or the pressure of a gas or a liquid; the state of the fluid between a liquid and a gas; and/or the composition of the gas or liquid. “Indirect fluid flow”, as defined herein, excludes changing the composition of the gas or liquid between the two defined elements by chemical reaction, for example, oxidation or reduction of one or more elements of the liquid or gas.

The asphaltene solvent provided for use in the method or system of the present invention is comprised of at least 75 mol % DMS. The asphaltene solvent may be comprised of at least 80 mol %, or at least 85 mol %, or at least 90 mol %, or at least 95 mol %, or at least 99 mol % DMS. The asphaltene solvent may consist essentially of DMS, or may consist of DMS.

The asphaltene solvent provided for use in the method or system of the present invention may be comprised of one or more compounds that form a mixture with the DMS in the solvent. The one or more compounds may be compounds that form an azeotropic mixture with DMS. Compounds that may form an azeotropic mixture with DMS that may be included in the asphaltene solvent are pentane, isopentane, 2-methyl-2-butene, and isoprene. The asphaltene solvent, therefore, may be comprised of at least 75 mol % DMS and one or more compounds selected from the group consisting of pentane, isopentane, 2-methyl-2-butene, and isoprene.

The asphaltene solvent may also include one or more other compounds that do not form azeotropic mixtures with DMS in which asphaltenes are soluble at temperatures within the range of temperatures in the formation, or from 5° C. to 300° C. The one or more other compounds may be selected from the group consisting of o-xylene, toluene, carbon disulfide, dichloromethane, trichloromethane, natural gas condensates, hydrogen sulfide, diesel, naphtha solvent, asphalt solvent, kerosene, and dimethyl ether.

The asphaltene solvent may include a fluid that has a density greater than DMS, and preferably greater than oil in the formation. The fluid having a density greater than DMS may be included in the asphaltene solvent to increase the density of the solvent relative to the density of DMS to enhance plug flow of the solvent through the formation. The fluid having a density greater than DMS may have a density of at least 0.9 g/cm³ or at least 1.0 g/cm³. The fluid having a density greater than DMS may be decant oil. In an embodiment, the asphaltene solvent provided for use in the method or system of the present invention may be comprised of up to 25 mol % decant oil.

The asphaltene solvent provided for use in the method or system of the present invention may be first contact miscible with liquid petroleum compositions, preferably any liquid petroleum composition. In liquid phase or in gas phase the solvent may be first contact miscible with substantially all crude oils including light crude oils, heavy crude oils, extra-heavy crude oils, and bitumen, and may be first contact miscible in liquid phase or in gas phase with the oil in the oil-bearing formation.

The asphaltene solvent may be first contact miscible with liquid phase residue—hydrocarbons having a boiling point of at least 540° C. at 0.101 MPa—and liquid phase asphaltenes in a hydrocarbonaceous composition. The asphaltene solvent may dissolve at least a portion of asphaltene deposits in an oil-bearing formation including asphaltene sludges and solid asphaltene deposits within a formation, where the asphaltene deposits may be near-wellbore deposits induced, at least in part, by production of oil from the formation, or the asphaltene deposits may be naturally occurring tar mats. The asphaltene solvent may also be first contact miscible with C₃ to C₈ aliphatic and aromatic hydrocarbons containing less than 5 wt. % oxygen, less than 10 wt. % sulfur, and less than 5 wt. % nitrogen.

The asphaltene solvent may be first contact miscible with oil having a moderately high or a high viscosity. The asphaltene solvent may be first contact miscible with oil having a dynamic viscosity of at least 1000 mPa s (1000 cP), or at least 5000 mPa s (5000 cP), or at least 10000 mPa s (10000 cP), or at least 50000 mPa s (50000 cP), or at least 100000 mPa s (100000 cP), or at least 500000 mPa s (500000 cP) at 25° C. The asphaltene solvent may be first contact miscible with oil having a dynamic viscosity of from 1000 mPa s (1 cP) to 5000000 mPa s (5000000 cP), or from 5000 mPa s (100 cP) to 1000000 mPa s (1000000 cP), or from 10000 mPa s (500 cP) to 500000 mPa s (500000 cP), or from 50000 mPa s (1000 cP) to 100000 mPa s (100000 cP) at 25° C.

The asphaltene solvent provided for use in the method or system of the present invention may have a low viscosity. The asphaltene solvent may be a fluid having a dynamic viscosity of at most 0.35 mPa s (0.35 cP), or at most 0.3 mPa s (0.3 cP), or at most 0.285 mPa s (0.285 cP) at a temperature of 25° C.

The asphaltene solvent provided for use in the method or system of the present invention may have a relatively high cohesive energy density. The asphaltene solvent provided for use in the method or system of the present invention may have a cohesive energy density of at least 300 Pa to 410 Pa, or from 320 Pa to 400 Pa.

The asphaltene solvent provided for use in the method or system of the present invention preferably is relatively non-toxic or is non-toxic. The asphaltene solvent may have an aquatic toxicity of LC₅₀ (rainbow trout) greater than 200 mg/l at 96 hours. The asphaltene solvent may have an acute oral toxicity of LD₅₀ (mouse and rat) of from 535 mg/kg to 3700 mg/kg, an acute dermal toxicity of LD₅₀ (rabbit) of greater 5000 mg/kg, and an acute inhalation toxicity of LC₅₀ (rat) of 40250 ppm at 4 hours.

Referring now to FIG. 1, a system of the invention useful for practicing a process of the present invention is shown. An asphaltene solvent comprising at least 75 mol. % DMS as described above is provided and stored in an asphaltene solvent storage facility 101. The asphaltene solvent storage facility 101 is operatively fluidly coupled to a well 103. The well 103 extends into an oil-bearing formation 105 containing one or more asphaltene deposits 107, and is positioned to introduce the asphaltene solvent into the formation to contact an asphaltene deposit therein.

The oil-bearing formation 105 may be a subterranean formation. The subterranean formation may be comprised of one or more porous matrix materials selected from the group consisting of a porous mineral matrix, a porous rock matrix, and a combination of a porous mineral matrix and a porous rock matrix, where the porous matrix material may be located beneath an overburden at a depth ranging from 50 meters to 6000 meters, or from 100 meters to 4000 meters, or from 200 meters to 2000 meters under the earth's surface. The formation may have a permeability of from 0.000001 to 15 Darcies, or from 0.001 to 1 Darcy. The rock and/or mineral porous matrix material of the formation may be comprised of sandstone, shale, and/or a carbonate selected from dolomite, limestone, and mixtures thereof—where the limestone may be microcrystalline or crystalline limestone and/or chalk. The subterranean formation may be a subsea subterranean formation.

One or more asphaltene deposits 107 are located in the formation 105. An asphaltene deposit may be comprised of a solid accumulation of asphaltenes that have deposited on mineral or rock surfaces within the formation. An asphaltene deposit may be comprised of a sludge of asphaltenes that has settled out of the oil in the formation. An asphaltene deposit 107 may impede fluid flow through the portion of the formation 105 in which the deposit is located, wherein the asphaltene deposit may have accumulated in pores of the porous rock or mineral matrix of the formation, thereby reducing the permeability of the formation to the flow of fluids. An asphaltene deposit 107 may be a near-wellbore deposit that has accumulated near the wellbore 109 within the formation 105, for example, within 5 meters of the wellbore. A near-wellbore asphaltene deposit may have resulted from producing oil from the formation 105 through the well 103, for example, by changing pressure, temperature, composition, and/or shear rate. An asphaltene deposit 107 may be a naturally occurring tar mat or a tar mat formed as a result of producing oil from the formation.

The well 103 is structured and arranged to introduce the asphaltene solvent into the oil-bearing formation in position to contact an asphaltene deposit 107 therein. The well 103 may be operatively fluidly coupled to the asphaltene solvent storage facility 101 through an injection/production facility 111. The asphaltene solvent storage facility 101 may be operatively fluidly coupled to the injection/production facility 111 via conduit 113 to provide asphaltene solvent to the injection/production facility. The injection/production facility 111 may be operatively fluidly coupled to the well 103 to provide the asphaltene solvent to the well. As shown by the down arrow in the well 103, the asphaltene solvent may flow from the injection/production facility 111 through the well to be introduced into the formation 105 in position to contact the asphaltene deposit 107. The well 103 may be a conventional well for introducing or injecting a fluid into an oil-bearing formation wherein the well may contain conduits, tubes, or strings therein to conduct the asphaltene solvent from the injection/production facility 111 into the formation to a position from which the solvent may be introduced into the formation to contact an asphaltene deposit 107. The well 103 may have perforations in the wellbore at a location through which the solvent may be introduced into the formation to contact an asphaltene deposit.

The injection/production facility 111 and the well 103, or the well itself, may include a mechanism for introducing the asphaltene solvent into the formation 105. The mechanism for introducing the asphaltene solvent into the formation 105 may be comprised of a pump 115 for delivering the asphaltene solvent to perforations or openings in the well through which the asphaltene solvent may be injected into the formation in position to contact an asphaltene deposit 107. In one embodiment, the well 103 may comprise a pump and the asphaltene solvent may be provided directly from the asphaltene solvent storage facility 101 to the pump of the well for introduction into the formation in the absence of an injection/production facility 111.

The asphaltene solvent is introduced into the oil-bearing formation 105, for example by being injected into the formation by pumping the asphaltene solvent into the formation. The asphaltene solvent may be introduced into the formation at a pressure above the instantaneous pressure in the formation to force the asphaltene solvent to flow into the formation. The pressure at which the asphaltene solvent is introduced into the formation may range from the instantaneous pressure in the formation up to, but not including, the fracture pressure of the formation. The pressure at which the asphaltene solvent may be injected into the formation may range from 20% to 95%, or from 40% to 90%, of the fracture pressure of the formation. The pressure at which the asphaltene solvent is injected into the formation may range from a pressure from 0 to 37 MPa above the initial formation pressure as measured prior to the start of injection.

An amount of the asphaltene solvent may be introduced into the formation to contact and dissolve at least a portion of an asphaltene deposit 107. If the asphaltene deposit 107 is a near-wellbore deposit wherein the deposit is located in the formation within 5 meters of the well, a volume of asphaltene solvent sufficient to penetrate up to 5 meters radially from the well within the portion of the formation in which the deposit is located may be introduced into the formation. If the asphaltene deposit is located at a known distance greater than 5 meters from the well 103, a volume of asphaltene solvent sufficient to penetrate to the known distance radially from the well within the portion of the formation in which the asphaltene deposit is located may be introduced into the formation.

As the asphaltene solvent is introduced into the formation 105, the asphaltene solvent may spread into the formation as shown by arrows 117. Upon introduction to the formation 105, the asphaltene solvent may contact the asphaltene deposit 107. The asphaltenes of the asphaltene deposit 107 are very soluble in the asphaltene solvent, where the asphaltenes may be first contact miscible with the asphaltene solvent. The asphaltene solvent may solvate and mobilize at least a portion, and preferably substantially all, of the asphaltenes in the asphaltene deposit upon contact with the asphaltene deposit.

The asphaltene solvent may be left to soak in the formation 105 after introduction into the formation to contact, solvate, and mobilize the asphaltenes in the asphaltene deposit 107. The asphaltene solvent should be contacted with asphaltene deposit for a sufficient period of time to solvate at least a portion, and preferably substantially all, of the asphaltenes of the asphaltene deposit, for example, at least 50 wt. %, or at least 75 wt. %, or at least 90 wt. % of the asphaltenes in the asphaltene deposit that are contacted by the asphlatene solvent. The asphaltene solvent may be left to soak in the formation for a time period of from 1 hour to 15 days, or from 5 hours to 50 hours.

Subsequent to the introduction of the asphaltene solvent into the formation 105 and contact of the asphaltene solvent with the asphaltene deposit, a mixture of the asphaltene solvent and mobilized asphaltenes solvated by the solvent may be removed from the site of the (former) asphlatene deposit in the formation. The mixture of asphaltene solvent and mobilized asphaltenes may be removed from the site of the (former) asphaltene deposit in the formation by injecting additional asphaltene solvent into the formation, or by injecting another fluid, for example water, into the formation, or by producing the mixture of asphaltene solvent and mobilized asphaltenes from the formation.

Mobilization and removal of asphaltenes from the asphaltene deposit with the asphaltene solvent may increase the fluid permeability of the formation at the location of the former asphaltene deposit. The fluid permeability of the formation at the location of the former asphaltene deposit may be increased by at least 0.001 Darcy, or at least 0.01 Darcy, or at least 0.1 Darcy, or at least 0.5 Darcy by mobilization and removal of asphaltenes from the asphaltene deposit with the asphaltene solvent.

The mixture of asphaltene solvent and mobilized asphaltenes may be recovered and produced from the formation 105, as shown in FIG. 2. The system may include a mechanism for producing the mixture of asphaltene solvent and mobilized asphaltenes from the formation 105 subsequent to introduction of the asphaltene solvent into the formation and contact of the asphaltene solvent with the asphaltene deposit, for example, after completion of introduction of the asphaltene solvent into the formation and following the soak period. The mechanism for recovering and producing the mixture of asphaltene solvent and asphaltenes may be comprised of a pump 112, which may be located in the injection/production facility 111 and/or within the well 103, and which draws the asphaltene solvent and the mixture of asphaltene solvent and mobilized asphaltenes from the formation to deliver the asphaltene solvent and the mixture of asphaltene solvent and mobilized asphaltenes to the facility 111.

Alternatively, the mechanism for recovering and producing the mixture of asphaltene solvent and mobilized asphaltenes from the formation 105 may be comprised of a compressor 114. The compressor 114 may be operatively fluidly coupled to a gas storage tank 119 by conduit 121, and may compress gas from the gas storage tank for injection into the formation 105 through the well 103. The compressor may compress the gas to a pressure sufficient to drive production of the mixture of asphaltene solvent and mobilized asphaltenes from the formation 105 via the well 103, where the appropriate pressure can be determined by conventional methods known to those skilled in the art. The compressed gas may be injected into the formation from a different position on the well 103 than the well position at which the mixture of asphaltene solvent and mobilized asphaltenes are produced from the formation.

Oil, and optionally gas and water, also may be mobilized and recovered from the formation 105 while recovering and producing the mixture of asphaltene solvent and mobilized asphaltenes from the formation. Oil may be recovered and produced from the formation 105, in part, through the portion of the formation from which at least a part of the asphaltene deposit has been removed due to the increased fluid permeability of the formation.

The mixture of asphaltene solvent and mobilized asphaltenes, and optionally oil, water, and gas may be drawn from the formation 105 as shown by arrows 123 and produced back up the well 103 to the injection/production facility 103. The produced mobilized asphaltenes, optionally together with produced oil, may be separated from the produced asphaltene solvent, and optionally produced water and gas, in a separation unit 125. The separation unit 125 may be comprised of a conventional flash or distillation column for separating the produced asphaltene solvent from the produced mobilized asphaltenes, and optionally produced oil and produced water. The separation unit may also be comprised of a conventional liquid-gas separator for separating produced gas from the produced mobilized asphaltenes and produced asphaltene solvent—and optionally produced oil and produced water, and a conventional water knockout vessel for separating the produced mobilized asphaltenes—and optionally produced oil—from produced water.

The separated produced asphaltenes, and optionally produced oil, may be provided from the separation unit 125 of the injection/production facility 111 to a liquid storage tank 127, which may be operatively fluidly coupled to the separation unit of the injection/production facility by conduit 129. The separated produced gas, if any, may be provided from the separation unit 125 of the injection/production facility 111 to the gas storage tank 119, which may be operatively fluidly coupled to the separation unit of the injection/production facility by conduit 131. The separated produced asphaltene solvent may be provided from the separation unit 125 of the injection/production facility 111 to the asphaltene solvent storage facility 101 via conduit 133.

After dissolving at least a portion of the asphaltene deposit 107 in the formation 105 by introducing the asphaltene solvent into the formation and contacting the asphaltene solvent with the asphaltene deposit to mobilize at least a portion of the asphaltenes therein, oil may be produced from the formation 105 through the portion of the formation previously occupied by the asphaltene deposit. As noted above, removal of at least a portion of the asphaltene deposit 107 by contact with the asphaltene solvent may increase the fluid permeability of the formation 105 at the location of the former asphaltene deposit. Oil which could not be produced from the formation 105, or which could be produced only in limited quantities, due to the asphaltene deposit 107 may be produced from the formation. Oil recovery and production from the formation 105 may be effected in accordance with conventional oil recovery processes and techniques after removal of at least a portion of the asphaltene deposit with the asphaltene solvent. For example, after removal of at least a portion of an asphaltene deposit, oil recovery may be effected by cyclic steam stimulation or by cyclic injection and recovery of an oil miscible oil recovery formulation. In one embodiment, the oil miscible oil recovery formulation may be the asphaltene solvent.

Referring now to FIG. 3, a system 300 of the present invention for practicing a method of the present invention is shown. The system includes a first well 301 and a second well 303 extending into an oil-bearing formation 305, where the first well is structured and arranged to introduce an asphaltene solvent into the formation and a second well is structured and arranged to produce oil from the formation, and, optionally to produce a mixture of the asphaltene solvent and asphaltenes from the formation. The oil-bearing formation 305 contains one or more asphaltene deposits 311 therein. The first well 301 extends into the formation in position to introduce an asphaltene solvent into the formation to contact an asphaltene deposit 311 therein, where the asphaltene deposit may be on a fluid flow path from the first well.

An asphaltene solvent comprising at least 75 mol % DMS as described above is provided and may be stored in an asphaltene solvent storage facility 315. The asphaltene solvent may be provided from the asphaltene solvent storage facility 315 to an injection facility 317 via conduit 319, where the asphaltene solvent storage facility may be operatively fluidly coupled to the injection facility.

The injection facility 317 may be operatively fluidly coupled to the first well 301. The asphaltene solvent may flow from the injection facility 317 through the first well 301 to be introduced into the formation 305. The injection facility 317 may include a mechanism such as a pump 321 for introducing the asphaltene solvent into the formation through the first well 301. Alternatively, the asphaltene solvent may flow from the asphaltene solvent storage facility 315 directly to the first well 301 for injection into the formation 305, where the first well comprises a mechanism such as a pump for introducing the asphaltene solvent into the formation.

As shown by the down arrow in the first well 301, the asphaltene solvent may flow through the first well to be introduced into the formation 305 in position to contact the asphaltene deposit 311. The first well 301 may be a conventional well for introducing or injecting a fluid into an oil-bearing formation wherein the first well may contain conduits, tubes, or strings therein to conduct the asphaltene solvent to a position from which the solvent may be introduced into the formation to contact an asphaltene deposit 311. The first well 301 may have perforations in the wellbore at a location through which the solvent may be introduced into the formation to contact an asphaltene deposit. The asphaltene solvent may be introduced into the formation 305 by injecting the asphaltene solvent into the formation through the first well 301 at pressures as described above.

The asphaltene deposit 311 may lie along a fluid flow path from the first well 301, wherein the asphaltene solvent may proceed along the fluid flow path in the formation as shown by arrows 323 to contact the asphaltene deposit upon being introduced into the formation. The asphaltene deposit 311 may be a near-wellbore deposit or the asphaltene deposit may lie a substantial distance from the first well 301, for example greater than 5 meters, or greater than 10 meters, or greater than 25 meters, or greater than 50 meters. If the asphaltene deposit 311 lies a substantial distance from the first well 301, the asphaltene deposit may be a naturally occurring tar mat. The asphaltene deposit 311 may lie along a fluid flow path between the first well 301 and the second well 303. The asphaltene deposit 311 may impede or block fluid flow along the flow path between the first well 301 and the second well 303.

The volume of asphaltene solvent introduced into the formation 305 via the first well 301 may range from 0.001 to 5 pore volumes, or from 0.01 to 2 pore volumes, or from 0.1 to 1 pore volumes, or from 0.2 to 0.6 pore volumes, where the term “pore volume” refers to the volume of the formation that may be swept by the asphaltene solvent between the first well 301 and the second well 303. This pore volume may be readily be determined by methods known to a person skilled in the art, for example by modelling studies or by injecting water having a tracer contained therein through the formation 305 from the first well 301 to the second well 303.

As the asphaltene solvent is introduced into the formation 305, the solvent spreads into the formation as shown by arrows 323. Upon introduction to the formation 305 and subsequently reaching an asphaltene deposit 311, the asphaltene solvent may contact the asphaltene deposit 311. The asphaltenes of the asphaltene deposit are very soluble in the asphaltene solvent, where the asphaltenes may be first contact miscible with the asphaltene solvent. The asphaltene solvent may solvate and mobilize at least a portion of the asphaltenes in the asphaltene deposit 311 upon contact with the asphaltene deposit, forming a mixture of the asphaltene solvent and mobilized asphaltenes.

Additional asphaltene solvent or another fluid such as water or brine or an oil recovery formulation may be introduced into the formation through the first well to remove the mixture of the asphaltene solvent and mobilized asphaltenes from the site of the asphaltene deposit. The mixture of asphaltene solvent and mobilized asphaltenes may be pushed through the formation from the former asphaltene deposit to the second well 303 along the fluid flow path between the first and second wells 301 and 303 as shown by arrows 329. The mixture of asphaltene solvent and mobilized asphaltenes may then be produced from the formation through the second well.

Mobilization and removal of asphaltenes from the site of the asphaltene deposit 311 may increase the permeability of the formation for fluid flow at the location of the former asphaltene deposit. The fluid permeability of the formation at the location of the former asphaltene deposit may be increased by at least 0.001 Darcy, or at least 0.01 Darcy, or at least 0.1 Darcy, or at least 0.5 Darcy by mobilization and removal of asphaltenes from the asphaltene deposit with the asphaltene solvent. Fluid flow along the fluid flow path between the first well 301 and the second well 303 may be improved by increasing the fluid permeability of the formation 305 at the location of the former asphaltene deposit.

The mixture of the asphaltene solvent and mobilized asphaltenes may be pushed across the formation 305 from the first well 301 to the second well 303 by introduction of an oil immiscible formulation into the formation subsequent to introduction of the asphaltene solvent into the formation. The oil immiscible formulation may be introduced into the formation 305 through the first well 301 after completion of introduction of the asphaltene solvent into the formation to force or otherwise displace the mixture of the asphaltene solvent and mobilized asphaltenes from the asphaltene deposit, preferably toward the second well 303.

The oil immiscible formulation may be configured to displace the mixture of asphaltene solvent and mobilized asphaltenes through the formation 305. Suitable oil immiscible formulations are not first contact miscible or multiple contact miscible with the asphaltene solvent or a mixture of the asphaltene solvent and asphaltenes or oil in the formation. The oil immiscible formulation may be water, brine, or an aqueous polymer fluid. Suitable polymers for use in an aqueous polymer fluid may include, but are not limited to, polyacrylamides, partially hydrolyzed polyacrylamides, polyacrylates, ethylenic copolymers, biopolymers, carboxymethylcellulose, polyvinyl alcohols, polystyrene sulfonates, polyvinylpyrolidones, AMPS (2-acrylamide-2-methyl propane sulfonate), combinations thereof, or the like. Examples of ethylenic copolymers include copolymers of acrylic acid and acrylamide, acrylic acid and lauryl acrylate, lauryl acrylate and acrylamide. Examples of biopolymers include xanthan gum, guar gum, alginic acids, and alginate salts.

The oil immiscible formulation may be stored in, and provided for introduction into the formation 305 from, an oil immiscible formulation storage facility 325 that may be operatively fluidly coupled to the injection facility 317 via conduit 327. The injection facility 317 may be operatively fluidly coupled to the first well 301 to provide the oil immiscible formulation to the first well for introduction into the formation 305. Alternatively, the oil immiscible formulation storage facility 325 may be operatively fluidly coupled to the first well 301 directly to provide the oil immiscible formulation to the first well for introduction into the formation 305. The injection facility 317 and the first well 301, or the first well itself, may comprise a mechanism for introducing the oil immiscible formulation into the formation 305 via the first well 301. The mechanism for introducing the oil immiscible formulation into the formation 305 via the first well 301 may be comprised of a pump or a compressor for delivering the oil immiscible formulation to perforations or openings in the first well through which the oil immiscible formulation may be injected into the formation. The mechanism for introducing the oil immiscible formulation into the formation 305 via the first well 301 may be the pump 321 utilized to inject the asphaltene solvent into the formation via the first well 301, where the oil immiscible formulation may be introduced into the formation by injecting the oil immiscible formulation into the formation at pressures of from the instantaneous pressure of the formation up to, but not including, the fracture pressure of the formation.

An oil recovery formulation may be introduced into the formation through the first well 301 at pressures of from the instantaneous pressure of the formation up to, but not including, the fracture pressure of the formation 305 following introduction of the asphaltene solvent into the formation, or simultaneously with the introduction of the asphaltene solvent into the formation, or after injection of the oil immiscible formulation into the formation to enhance recovery of oil from the formation through the second well 303. The oil recovery formulation may proceed through the formation along the fluid flow path as shown by arrows 323 and 329 mobilizing oil in the formation for production from the formation through the second well 303. The oil recovery formulation and the mobilized oil may flow through the site of the former asphaltene deposit 311 in the formation due to the improved permeability of the formation resulting from dissolution of the asphaltene deposit into the asphaltene solvent. The oil recovery formulation and mobilized oil may be produced from the formation through the second well 303. The oil recovery formulation may be a formulation utilized to improve or enhance recovery of oil from an oil-bearing formation including water, brine, low salinity water having a total dissolved solids content of from 500 parts per million (“ppm”) to 10000 ppm and a total ionic strength of at most 0.15M, conventional alkali-surfactant-polymer enhanced oil recovery formulations, dimethyl ether, carbon disulfide, or dimethyl sulfide.

The oil recovery formulation may be stored in, and provided for introduction into the formation 305 from, an oil recovery formulation storage facility 326 that may be operatively fluidly coupled to the injection facility 317 via conduit 328. The injection facility 317 may be operatively fluidly coupled to the first well 301 to provide the oil recovery formulation to the first well for introduction into the formation 305. Alternatively, the oil recovery formulation storage facility 326 may be operatively fluidly coupled to the first well 301 directly to provide the oil recovery formulation to the first well for introduction into the formation 305. The injection facility 317 and the first well 301, or the first well itself, may comprise a mechanism for introducing the oil recovery formulation into the formation 305 via the first well 301. The mechanism for introducing the oil recovery formulation into the formation 305 via the first well 301 may be comprised of a pump or a compressor for delivering the oil recovery formulation to perforations or openings in the first well through which the oil recovery formulation may be injected into the formation. The mechanism for introducing the oil recovery formulation into the formation 305 via the first well 301 may be the pump 321 utilized to inject the asphaltene solvent into the formation via the first well 301.

The mixture of asphaltene solvent and mobilized asphaltenes and optionally oil, water, and gas may be recovered and produced from the formation 305 through the second well 303. The system may include a mechanism for producing the mixture of asphaltene solvent and mobilized asphaltenes from the formation 305 subsequent to introduction of the asphaltene solvent into the formation, for example, after completion of introduction of the asphaltene solvent into the formation and arrival of the mixture of asphaltene solvent and mobilized asphaltenes at the second well 303, after the introduction of the oil immiscible formulation into the formation, or after the introduction of the oil recovery formulation into the formation and arrival of mobilized oil and the oil recovery formulation at the second well. The mechanism for recovering and producing the mixture of asphaltene solvent and mobilized asphaltenes, and optionally oil, water, and/or gas may be comprised of a pump 333, which may be located in a production facility 331 and/or within the second well 303, and which draws the mixture of asphaltene solvent and mobilized asphaltenes from the formation, and optionally oil, water, and/or gas, to deliver the mixture of asphaltene solvent and mobilized asphaltenes, and optionally oil, water, and/or gas to the production facility 331.

Alternatively, the mechanism for recovering and producing the mixture of asphaltene solvent and mobilized asphaltenes from the formation 305 through the second well 303 may be comprised of a compressor 334. The compressor 334 may be operatively fluidly coupled to a gas storage tank 341 by conduit 353, and may compress gas from the gas storage tank for injection into the formation 305 through the second well 303. The compressor 334 may compress gas from a gas storage tank for injection into the formation 305 through the second well 303. The compressor may compress the gas to a pressure sufficient to drive production of the mixture of asphaltene solvent and mobilized asphaltenes from the formation via the second well 303, where the appropriate pressure can be determined by conventional methods known to those skilled in the art. The compressed gas may be injected into the formation from a different position on the second well 303 than the position in the second well at which the mixture of asphaltene solvent and mobilized asphaltenes are produced from the formation.

Oil, and optionally water, the oil recovery formulation, and/or gas, also may be mobilized and recovered from the formation 305 while recovering and producing the mixture of asphaltene solvent and mobilized asphaltenes from the formation. Oil may be recovered and produced from the formation 305, in part, through the portion of the formation from which at least a part of the asphaltene deposit 311 has been removed due to the increased fluid permeability of the formation. The oil, in part, may be oil mobilized by the oil recovery formulation. Oil, and optionally water, the oil recovery formulation, and/or gas may be continue to be recovered from the formation 305 after recovery of the mixture of the asphaltene solvent and asphaltenes is complete as a result of ongoing oil recovery from the formation once the blockage caused by asphaltene deposit 311 has been remediated by contact with the asphaltene solvent.

The mixture of asphaltene solvent and mobilized asphaltenes, oil, and optionally oil recovery formulation, water, and/or gas may be produced up the second well 303 to the production facility 331. The produced mobilized asphaltenes, together with produced oil, may be separated from the produced asphaltene solvent, and optionally produced oil recovery formulation, produced water, and/or produced gas, in a separation unit 335 in the production facility 331. The separation unit may be comprised of a conventional flash or distillation column for separating the produced asphaltene solvent and, optionally the produced oil recovery formulation, from the produced mobilized asphaltenes and produced oil, and optionally from the produced water and/or produced gas. The separation unit 335 may also be comprised of a conventional liquid-gas separator for separating produced gas from the produced mobilized asphaltenes, produced oil, and produced asphaltene solvent, and optionally produced water and/or produced oil recovery formulation, and a conventional water knockout vessel for separating the produced mobilized asphaltenes and produced oil from produced water.

The separated produced asphaltenes and produced oil may be provided from the separation unit 335 of the production facility 331 to an oil storage tank 337, which may be operatively fluidly coupled to the separation unit of the production facility by conduit 339. The separated produced gas, if any, may be provided from the separation unit 335 of the production facility 331 to the gas storage tank 341, which may be operatively fluidly coupled to the separation unit of the injection/production facility by conduit 343. The separated produced oil recovery formulation, if any, may be provided from the separation unit 335 of the production facility 331 to the oil recovery formulation storage facility 326, which may be operatively fluidly coupled to the separation unit of the production facility 331 by conduit 366. The separated produced asphaltene solvent may be provided from the separation unit 335 of the production facility 331 to the asphaltene solvent storage facility 315 via conduit 349.

To facilitate a better understanding of the present invention, the following examples of certain aspects of some embodiments are given. In no way should the following examples be read to limit, or define, the scope of the invention.

Example 1

The quality of dimethyl sulfide as an asphaltene solvent based on the miscibility of dimethyl sulfide with a crude oil relative to other compounds was evaluated. The miscibility of dimethyl sulfide, ethyl acetate, o-xylene, carbon disulfide, chloroform, dichloromethane, tetrahydrofuran, and pentane solvents with mined oil sands was measured by extracting the oil sands with the solvents at 10° C. and at 30° C. to determine the fraction of hydrocarbons extracted from the oil sands by the solvents. The bitumen content of the mined oil sands was measured at 11 wt. % as an average of bitumen extraction yield values for solvents known to effectively extract substantially all of bitumen from oil sands—in particular chloroform, dichloromethane, o-xylene, tetrahydrofuran, and carbon disulfide. One oil sands sample per solvent per extraction temperature was prepared for extraction, where the solvents used for extraction of the oil sands samples were dimethyl sulfide, ethyl acetate, o-xylene, carbon disulfide, chloroform, dichloromethane, tetrahydrofuran, and pentane. Each oil sands sample was weighed and placed in a cellulose extraction thimble that was placed on a porous polyethylene support disk in a jacketed glass cylinder with a drip rate control valve. Each oil sands sample was then extracted with a selected solvent at a selected temperature (10° C. or 30° C.) in a cyclic contact and drain experiment, where the contact time ranged from 15 to 60 minutes. Fresh contacting solvent was applied and the cyclic extraction repeated until the fluid drained from the apparatus became pale brown in color.

The extracted fluids were stripped of solvent using a rotary evaporator and thereafter vacuum dried to remove residual solvent. The recovered bitumen samples all had residual solvent present in the range of from 3 wt. % to 7 wt. %. The residual solids and extraction thimble were air dried, weighed, and then vacuum dried. Essentially no weight loss was observed upon vacuum drying the residual solids, indicating that the solids did not retain either extraction solvent or easily mobilized water. Collectively, the weight of the solid sample and thimble recovered after extraction plus the quantity of bitumen recovered after extraction divided by the weight of the initial oil sands sample plus the thimble provide the mass closure for the extractions. The calculated percent mass closure of the samples was slightly high because the recovered bitumen values were not corrected for the 3 wt. % to 7 wt. % residual solvent. The extraction experiment results are summarized in Table 1.

TABLE 1 Summary of Extraction Experiments of Bituminous Oil Sands with Various Fluids Input Output Experimental Solids Solids Weight Recovered Weight Extraction Fluid Temperature, C. weight, g weight, g Change, g Bitumen, g Closure, % Carbon Disulfide 30 151.1 134.74 16.4 16.43 100.0 Carbon Disulfide 10 151.4 134.62 16.8 16.62 99.9 Chloroform 30 153.7 134.3 19.4 18.62 99.5 Chloroform 10 156.2 137.5 18.7 17.85 99.5 Dichloromethane 30 155.8 138.18 17.7 16.30 99.1 Dichloromethane 10 155.2 136.33 18.9 17.66 99.2 o-Xylene 30 156.1 136.58 19.5 17.37 98.6 o-Xylene 10 154.0 136.66 17.3 17.36 100.0 Tetrahydrofuran 30 154.7 136.73 18.0 17.67 99.8 Tetrahydrofuran 10 154.7 136.98 17.7 16.72 99.4 Ethyl Acetate 30 153.5 135.81 17.7 11.46 96.0 Ethyl Acetate 10 155.7 144.51 11.2 10.32 99.4 Pentane 30 154.0 139.11 14.9 13.49 99.1 Pentane 10 152.7 138.65 14.1 13.03 99.3 Dimethyl Sulfide 30 154.2 137.52 16.7 16.29 99.7 Dimethyl Sulfide 10 151.7 134.77 16.9 16.55 99.7

FIG. 4 provides a graph plotting the weight percent yield of extracted bitumen as a function of the extraction fluid at 30° C. applied with a correction factor for residual extraction fluid in the recovered bitumen, and FIG. 5 provides a similar graph for extraction at 10° C. without a correction factor. FIGS. 4 and 5 and Table 1 show that dimethyl sulfide is comparable for recovering bitumen from an oil sand material with the best known fluids for recovering bitumen from an oil sand material—o-xylene, chloroform, carbon disulfide, dichloromethane, and tetrahydrofuran—and is significantly better than pentane and ethyl acetate.

The bitumen samples extracted at 30° C. from each oil sands sample were evaluated by SARA analysis to determine the saturates, aromatics, resins, and asphaltenes composition of the bitumen samples extracted by each solvent. The results are shown in Table 2.

TABLE 2 SARA Analysis of Extracted Bitumen Samples as a Function of Extraction Fluid Oil Composition Normalized Weight Percent Extraction Fluid Saturates Aromatics Resins Asphaltenes Ethyl Acetate 21.30 53.72 22.92 2.05 Pentane 22.74 54.16 22.74 0.36 Dichloromethane 15.79 44.77 24.98 14.45 Dimethyl Sulfide 15.49 47.07 24.25 13.19 Carbon Bisulfide 18.77 41.89 25.49 13.85 o-Xylene 17.37 46.39 22.28 13.96 Tetrahydrofuran 16.11 45.24 24.38 14.27 Chloroform 15.64 43.56 25.94 14.86

The SARA analysis showed that pentane and ethyl acetate were much less effective for extraction of asphaltenes from oil sands than are the known highly effective asphaltene extraction fluids dichloromethane, carbon disulfide, o-xylene, tetrahydrofuran, and chloroform. The SARA analysis also showed that dimethyl sulfide has excellent miscibility properties for even the most difficult hydrocarbons-asphaltenes.

The data showed that dimethyl sulfide is generally as good as the recognized very good asphaltene extraction fluids for removal of asphaltenes from oil sands. The data also show that DMS is highly compatible with all classes of crude oil hydrocarbons—saturates, aromatics, resins, and asphaltenes, and, therefore, is unlikely to induce phase instability in crude oil upon introduction into an oil-bearing formation.

Example 2

Two experiments were conducted on a naturally occurring tar mat material recovered from an oil-bearing formation to compare the rate of dissolution of the tar mat material using dimethyl sulfide and A150, a commercially available solvent comprised of a mixture of aromatic hydrocarbons that is commonly used to dissolve tar mats. A naturally occurring tar mat material recovered from an oil-bearing formation at a depth of 4690 meters and at a formation temperature of 50° C. was utilized as the tar mat material for the comparison.

In the first experiment, two samples of DMS solvent and two samples of A150 solvent were individually mixed with the tar mat material at ambient temperature and pressure, where the volume (ml) to weight (g) ratio of each solvent sample to the tar mat material was approximately 100:1. The length of time required to entirely dissolve the tar mat material was measured and recorded. Table 3 below shows the results.

TABLE 3 Time Required for Dissolution of Tar Mat Material Weight of Tar Mat Volume of Time Until Sample Material Solvent Dissolution # Solvent (g) (ml) (h) 1 A150 1.07 100 Between 8.00 and 22.00 (overnight) 2 A150 1.07 100 Between 8:00 and 22:00 (overnight) 1 DMS 1.07 100 4:00 2 DMS 1.07 100 4:00

In the second experiment, four samples of DMS solvent and four samples of A150 solvent were individually mixed with the tar mat material at ambient temperature and pressure, where the volume (ml) to weight (g) ratio of each solvent sample to the tar mat material was approximately 10:1. The length of time required to entirely dissolve the tar mat material was measured and recorded. Table 4 below shows the results.

TABLE 4 Time Required for Dissolution of Tar Mat Material Weight of Tar Mat Volume of Time Until Sample Material Solvent Dissolution # Solvent (g) (ml) (h) 1 A150 1.02 10 Between 8.00 and 22.00 (overnight) 2 A150 1.00 10 Between 8:00 and 22:00 (overnight) 3 A150 1.02 10 Between 8:00 and 22:00 (overnight) 4 A150 1.02 10 Between 8:00 and 22:00 (overnight) 1 DMS 1.00 10 5:48 2 DMS 1.01 10 5:01 3 DMS 1.00 10 5:03 4 DMS 0.99 10 7:28

As shown by the results of each of the experiments, DMS dissolved the naturally occurring tar mat material at a higher rate than A150. In particular, DMS dissolved the naturally occurring tar mat material at a rate that was not less than 1.4 times faster than the A150 solvent. This data shows that DMS is an effective solvent for dissolving tar mat materials, and that DMS dissolves tar mat materials faster than A150, a commercially utilized solvent for dissolving tar mat materials.

The present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. While systems and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from a to b,” or, equivalently, “from a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Whenever a numerical range having a specific lower limit only, a specific upper limit only, or a specific upper limit and a specific lower limit is disclosed, the range also includes any numerical value “about” the specified lower limit and/or the specified upper limit. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an”, as used in the claims, are defined herein to mean one or more than one of the element that it introduces. 

What is claimed:
 1. A method for remediating asphaltene deposition in an oil-bearing formation, comprising: providing an asphaltene solvent comprising at least 75 mol % dimethyl sulfide (DMS); introducing the asphaltene solvent into an oil-bearing formation containing one or more asphaltene deposits; and contacting the asphaltene solvent with one or more of the asphaltene deposits in the formation.
 2. The method of claim 1 further comprising producing the asphaltene solvent from the formation after introducing the asphaltene solvent into the formation.
 3. The method of claim 1 further comprising producing oil from the formation after introducing the asphaltene solvent into the formation.
 4. The method of claim 1 wherein the asphaltene solvent is introduced into the formation through a first well.
 5. The method of claim 4 further comprising producing oil from the formation through the first well after introducing the asphaltene solvent into the formation through the first well.
 6. The method of claim 4 wherein the asphaltene deposits are located in the formation within 5 meters of the first well.
 7. The method of claim 6 wherein a volume of solvent sufficient to penetrate up to 5 meters radially from the first well is introduced into the formation through the first well.
 8. The method of claim 4 further comprising producing oil from the formation through a second well after introducing the asphaltene solvent into the formation through the first well.
 9. The method of claim 8 where from 0.1 to 2 pore volumes of the asphaltene solvent are introduced into the formation through the first well.
 10. The method of claim 1 wherein one or more of the asphaltene deposits form a tar mat in the formation.
 11. The method of claim 10 wherein the first well is located in the formation within 10 meters of the tar mat.
 12. The method of claim 1 wherein the asphaltene solvent is first contact miscible with oil in or from the formation.
 13. The method of claim 1 wherein the asphaltene solvent consists essentially of DMS.
 14. The method of claim 1 wherein the asphaltene solvent further comprises up to 25 mol % decant oil.
 15. The method of claim 1 wherein the asphaltene deposit is an asphaltene accretion on a portion of the formation or is a sludge.
 16. A system for remediating asphaltene deposition in an oil-bearing formation containing asphaltene deposits, comprising: an asphaltene solvent comprising at least 75 mol % dimethyl sulfide (DMS); an asphaltene solvent storage facility containing at least a portion of the asphaltene solvent; a well extending into the oil-bearing formation positioned to introduce the asphaltene solvent into the formation to contact an asphaltene deposit therein, the well being structured and arranged to introduce the asphaltene solvent into the oil-bearing formation to contact the asphaltene deposit therein, wherein the asphaltene solvent storage facility is operatively fluidly coupled to the first well to provide the asphaltene solvent to the first well.
 17. The system of claim 16 wherein the well is further structured and arranged to produce oil from the formation.
 18. The system of claim 17 wherein the well is further structured and arranged to produce the asphaltene solvent from the formation.
 19. The system of claim 16 wherein the well is a first well and further comprising a second well extending into the formation positioned to produce oil from the formation, wherein the second well is structured and arranged to produce oil from the formation.
 20. The system of claim 16 wherein the asphaltene solvent further comprises up to 25 mol % decant oil.
 21. The system of claim 16 wherein the asphaltene solvent consists essentially of DMS.
 22. The system of claim 16 wherein the asphaltene solvent is first contact miscible with oil in or from the formation. 